Document and Entity Information
Document and Entity Information - shares | 3 Months Ended | |
Mar. 31, 2017 | Apr. 28, 2017 | |
Document Information [Line Items] | ||
Document Type | 10-Q | |
Document Period End Date | Mar. 31, 2017 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Entity Central Index Key | 73,020 | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Registrant Name | Northwest Natural Gas Co. | |
Entity Voluntary Filers | No | |
Entity Well-known Seasoned Issuer | Yes | |
Entity Common Stock, Shares Outstanding | 28,644,327 | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q1 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Operating revenues [Abstract] | ||
Operating revenues | $ 297,323 | $ 255,529 |
Operating expenses: [Abstract] | ||
Cost of Gas | 143,611 | 108,411 |
Operations and maintenance | 40,420 | 38,939 |
Environmental Remediation Expense | 6,954 | 5,029 |
General taxes | 9,025 | 8,684 |
Depreciation and amortization | 21,085 | 20,394 |
Operating Costs and Expenses | 221,095 | 181,457 |
Income from operations | 76,228 | 74,072 |
Other income and (expense), net | 881 | (2,309) |
Interest Income (Expense), Nonoperating, Net | 9,876 | 9,736 |
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest | 67,233 | 62,027 |
Income tax expense | 26,923 | 25,386 |
Net Income | 40,310 | 36,641 |
Other comprehensive income: [Abstract] | ||
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax of $89 and $127 for the three months ended March 31, 2017 and 2016, respectively | 136 | 194 |
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | $ 40,446 | $ 36,835 |
Average common shares outstanding: [Abstract] | ||
Basic | 28,633 | 27,448 |
Diluted | 28,723 | 27,560 |
Earnings per share of common stock: [Abstract] | ||
Basic | $ 1.41 | $ 1.33 |
Diluted | 1.40 | 1.33 |
Dividends declared per share of common stock | $ 0.4700 | $ 0.4675 |
Consolidated Statements of Com3
Consolidated Statements of Comprehensive Income (Parentheticals) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Amortization of non-qualified employee benefit plan liability, tax | $ 89 | $ 127 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) | 3 Months Ended | ||
Mar. 31, 2017 | Dec. 31, 2016 | Mar. 31, 2016 | |
Statement of Financial Position [Abstract] | |||
Document Fiscal Year Focus | 2,017 | ||
Current assets: [Abstract] | |||
Cash and cash equivalents | $ 40,639,000 | $ 3,521,000 | $ 4,321,000 |
Accounts receivable | 70,429,000 | 66,700,000 | 69,066,000 |
Accrued unbilled revenue | 38,017,000 | 64,946,000 | 36,393,000 |
Allowance for uncollectible accounts | (1,668,000) | (1,290,000) | (1,376,000) |
Regulatory Assets, Current | 34,874,000 | 42,362,000 | 61,524,000 |
Derivative instruments | 2,908,000 | 17,031,000 | 1,960,000 |
Inventories | 48,484,000 | 54,129,000 | 60,581,000 |
Deferred Gas Cost | 15,378,000 | 15,926,000 | 16,420,000 |
Other current assets | 16,832,000 | 24,728,000 | 23,311,000 |
Total current assets | 265,893,000 | 288,053,000 | 272,200,000 |
Non-current assets: [Abstract] | |||
Property, plant, and equipment | 3,247,177,000 | 3,208,816,000 | 3,115,854,000 |
Less: Accumulated depreciation | 960,336,000 | 947,916,000 | 919,187,000 |
Total property, plant, and equipment, net | 2,286,841,000 | 2,260,900,000 | 2,196,667,000 |
Inventory, Gas in Storage Underground, Noncurrent | 96,630,000 | 100,184,000 | 111,145,000 |
Regulatory assets | 349,057,000 | 357,530,000 | 351,390,000 |
Derivative instruments | 46,000 | 3,265,000 | 452,000 |
Other investments | 68,729,000 | 68,376,000 | 67,490,000 |
Other non-current assets | 3,460,000 | 1,493,000 | 2,689,000 |
Total non-current assets | 2,804,763,000 | 2,791,748,000 | 2,729,833,000 |
Total assets | 3,070,656,000 | 3,079,801,000 | 3,002,033,000 |
Current liabilities: [Abstract] | |||
Short-term Debt | 0 | 53,300,000 | 164,900,000 |
Current maturities of long-term debt | 61,994,000 | 39,989,000 | 24,980,000 |
Accounts payable | 73,245,000 | 85,664,000 | 57,407,000 |
Taxes accrued | 16,653,000 | 12,149,000 | 10,256,000 |
Interest accrued | 10,581,000 | 5,966,000 | 9,671,000 |
Regulatory liabilities | 33,211,000 | 40,290,000 | 35,596,000 |
Derivative instruments | 1,638,000 | 1,315,000 | 17,313,000 |
Other current liabilities | 37,697,000 | 35,844,000 | 42,100,000 |
Total current liabilities | 235,019,000 | 274,517,000 | 362,223,000 |
Long-term debt | 657,716,000 | 679,334,000 | 569,745,000 |
Deferred credits and other non-current liabilities: [Abstract] | |||
Deferred tax liabilities | 575,451,000 | 557,085,000 | 550,731,000 |
Regulatory liabilities | 357,587,000 | 349,319,000 | 346,761,000 |
Pension and other postretirement benefit liabilities | 223,253,000 | 225,725,000 | 221,291,000 |
Derivative instruments | 2,546,000 | 913,000 | 1,237,000 |
Other non-current liabilities | 144,469,000 | 142,411,000 | 143,090,000 |
Total deferred credits and other non-current liabilities | 1,303,306,000 | 1,275,453,000 | 1,263,110,000 |
Commitments and contingencies (see Note 14 and Note 15) | |||
Equity: [Abstract] | |||
Common stock - no par value; authorized 100,000 shares; issued and outstanding 28,644, 27,493, and 28,630 at March 31, 2017 and 2016 and December 31, 2016, respectively | 442,647,000 | 445,187,000 | 385,232,000 |
Retained earnings | 438,783,000 | 412,261,000 | 428,691,000 |
Accumulated other comprehensive loss | (6,815,000) | (6,951,000) | (6,968,000) |
Total equity | 874,615,000 | 850,497,000 | 806,955,000 |
Total liabilities and equity | $ 3,070,656,000 | $ 3,079,801,000 | $ 3,002,033,000 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parentheticals) - USD ($) | Mar. 31, 2017 | Dec. 31, 2016 | Mar. 31, 2016 |
Common Stock Shares Authorized | 100,000,000 | 100,000,000,000 | 100,000,000 |
Common Stock, Shares, Outstanding | 28,644,000 | 28,630,000 | 27,493,000 |
Common Stock, Shares, Issued | 28,644,000 | 28,630,000 | 27,493,000 |
Commitments and Contingencies |
Consolidated Statement of Cash
Consolidated Statement of Cash Flows - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Operating activities: [Abstract] | ||
Net Income | $ 40,310 | $ 36,641 |
Adjustments to reconcile net income to cash provided by operations: [Abstract] | ||
Depreciation and amortization | 21,085 | 20,394 |
Regulatory amortization of gas reserves | 4,107 | 4,075 |
Deferred Tax Liabilities, net | 20,445 | 23,353 |
Qualified defined benefit pension plan expense | 1,316 | 1,311 |
Contributions to qualified defined benefit pension plans | (3,220) | (2,900) |
Deferred environmental (expenditures) recoveries, net | (3,432) | (2,665) |
Regulatory disallowance of prior environmental cost deferrals | 0 | 3,273 |
Amortization of environmental remediation | 6,954 | 5,029 |
Other | 1,695 | 1,169 |
Changes in assets and liabilities: [Abstract] | ||
Receivables, net | 23,147 | 22,242 |
Inventories | 5,645 | 10,115 |
Taxes Accrued | 4,504 | 7,729 |
Accounts payable | (13,437) | (14,537) |
Interest accrued | 4,615 | 3,798 |
Deferred gas costs | 13,454 | 8,519 |
Other, net | 17,978 | 18,592 |
Net Cash Provided by (Used in) Operating Activities, Continuing Operations | 145,166 | 146,138 |
Payments to Acquire Property, Plant, and Equipment [Abstract] | ||
Capital expenditures | (38,924) | (30,054) |
Other | 98 | 24 |
Net Cash Provided by (Used in) Investing Activities, Continuing Operations | (38,826) | (30,030) |
Financing activities: [Abstract] | ||
Repurchases related to stock-based compensation | (1,943) | (996) |
Proceeds from stock options exercised | 686 | 2,995 |
Change in short-term debt | (53,300) | (105,135) |
Cash dividend payments on common stock | (13,456) | (12,823) |
Other | (1,209) | (39) |
Net Cash Provided by (Used in) Financing Activities, Continuing Operations | (69,222) | (115,998) |
(Decrease) Increase in cash and cash equivalents | 37,118 | 110 |
Cash and cash equivalents, beginning of period | 3,521 | 4,211 |
Cash and cash equivalents, end of period | 40,639 | 4,321 |
Supplemental disclosure of cash flow information: [Abstract] | ||
Interest paid, net of capitalization | 4,394 | 5,232 |
Income Taxes Paid, Net of refunds | $ 3,040 | $ (7,900) |
Organization and Principles of
Organization and Principles of Consolidation | 3 Months Ended |
Mar. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block] | 1. ORGANIZATION AND PRINCIPLES OF CONSOLIDATION The accompanying consolidated financial statements represent the consolidated results of Northwest Natural Gas Company (NW Natural or the Company) and all companies we directly or indirectly control, either through majority ownership or otherwise. We have two core businesses: our regulated local gas distribution business, referred to as the utility segment, which serves residential, commercial, and industrial customers in Oregon and southwest Washington; and our gas storage businesses, referred to as the gas storage segment, which provides storage services for utilities, gas marketers, electric generators, and large industrial users from facilities located in Oregon and California. In addition, we have investments and other non-utility activities we aggregate and report as other. Our core utility business assets and operating activities are largely included in the parent company, NW Natural. Our direct and indirect wholly-owned subsidiaries include NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), Gill Ranch Storage, LLC (Gill Ranch), NNG Financial Corporation (NNG Financial), Northwest Energy Corporation (Energy Corp), and NWN Gas Reserves LLC (NWN Gas Reserves). Investments in corporate joint ventures and partnerships we do not directly or indirectly control, and for which we are not the primary beneficiary, are accounted for under the equity method, which includes NWN Energy’s investment in Trail West Holdings, LLC (TWH) and NNG Financial's investment in Kelso-Beaver (KB) Pipeline. NW Natural and its affiliated companies are collectively referred to herein as NW Natural. The consolidated financial statements are presented after elimination of all intercompany balances and transactions. In this report, the term “utility” is used to describe our regulated gas distribution business, and the term “non-utility” is used to describe our gas storage businesses and other non-utility investments and business activities. Information presented in these interim consolidated financial statements is unaudited, but includes all material adjustments management considers necessary for fair statement of the results for each period reported including normal recurring accruals. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in our 2016 Annual Report on Form 10-K (2016 Form 10-K). A significant part of our business is of a seasonal nature; therefore, results of operations for interim periods are not necessarily indicative of full year results. Certain prior year balances in our consolidated financial statements and notes have been reclassified to conform with the current presentation. These reclassifications had no effect on our prior year’s consolidated results of operations, financial condition, or cash flows. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 3 Months Ended |
Mar. 31, 2017 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies [Text Block] | 2. SIGNIFICANT ACCOUNTING POLICIES Our significant accounting policies are described in Note 2 of the 2016 Form 10-K. There were no material changes to those accounting policies during the three months ended March 31, 2017 . The following are current updates to certain critical accounting policy estimates and new accounting standards. Industry Regulation In applying regulatory accounting principles, we capitalize or defer certain costs and revenues as regulatory assets and liabilities pursuant to orders of the Public Utility Commission of Oregon (OPUC) or Washington Utilities and Transportation Commission (WUTC), which provide for the recovery of revenues or expenses from, or refunds to, utility customers in future periods, including a return or a carrying charge in certain cases. Amounts deferred as regulatory assets and liabilities were as follows: Regulatory Assets March 31, December 31, In thousands 2017 2016 2016 Current: Unrealized loss on derivatives (1) $ 1,580 $ 17,313 $ 1,315 Gas costs 2,757 7,978 6,830 Environmental costs (2) 7,574 9,096 9,989 Decoupling (3) 10,087 13,235 13,067 Other (4) 12,876 13,902 11,161 Total current $ 34,874 $ 61,524 $ 42,362 Non-current: Unrealized loss on derivatives (1) $ 2,546 $ 1,237 $ 913 Pension balancing (5) 53,105 46,247 50,863 Income taxes 36,591 40,106 38,670 Pension and other postretirement benefit liabilities 179,586 180,909 183,035 Environmental costs (2) 62,227 67,999 63,970 Gas costs 114 2,462 89 Decoupling (3) 2,803 2,641 5,860 Other (4) 12,085 9,789 14,130 Total non-current $ 349,057 $ 351,390 $ 357,530 Regulatory Liabilities March 31, December 31, In thousands 2017 2016 2016 Current: Gas costs $ 13,741 $ 22,098 $ 8,054 Unrealized gain on derivatives (1) 2,870 1,960 16,624 Other (4) 16,600 11,538 15,612 Total current $ 33,211 $ 35,596 $ 40,290 Non-current: Gas costs $ 4,740 $ 9,221 $ 1,021 Unrealized gain on derivatives (1) 46 452 3,265 Accrued asset removal costs (6) 345,614 331,000 341,107 Other (4) 7,187 6,088 3,926 Total non-current $ 357,587 $ 346,761 $ 349,319 (1) Unrealized gains or losses on derivatives are non-cash items and, therefore, do not earn a rate of return or a carrying charge. These amounts are recoverable through utility rates as part of the annual Purchased Gas Adjustment (PGA) mechanism when realized at settlement. (2) Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and WUTC. In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, recovery of deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from Oregon customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million tariff rider. The amounts allocable to Oregon are recoverable through utility rates, subject to the aforementioned earnings test. See Note 13 . (3) This deferral represents the margin adjustment resulting from differences between actual and expected volumes. (4) These balances primarily consist of deferrals and amortizations under approved regulatory mechanisms. The accounts being amortized typically earn a rate of return or carrying charge. (5) The deferral of certain pension expenses above or below the amount set in rates was approved by the OPUC, with recovery of these deferred amounts through the implementation of a balancing account, which includes the expectation of lower net periodic benefit costs in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the equity portion of interest income recognized when amounts are collected in rates. (6) Estimated costs of removal on certain regulated properties are collected through rates. We believe all costs incurred and deferred at March 31, 2017 are prudent. We annually review all regulatory assets and liabilities for recoverability and more often if circumstances warrant. If we should determine that all or a portion of these regulatory assets or liabilities no longer meet the criteria for continued application of regulatory accounting, then we would be required to write-off the net unrecoverable balances in the period such determination is made. New Accounting Standards We consider the applicability and impact of all accounting standards updates (ASUs) issued by the Financial Accounting Standards Board (FASB). Accounting standards updates not listed below were assessed and determined to be either not applicable or are expected to have minimal impact on our consolidated financial position or results of operations. Recently Adopted Accounting Pronouncements There were no material changes to the recently adopted accounting policies described in Note 2 of the 2016 Form 10-K during the three months ended March 31, 2017 . Recently Issued Accounting Pronouncements RETIREMENT BENEFITS. On March 10, 2017, the FASB issued ASU 2017-07, "Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Benefit Cost." The ASU requires entities to disaggregate current service cost from the other components of net periodic benefit cost and present it with other current compensation costs for related employees in the income statement and to present the other components elsewhere in the income statement and outside of income from operations if that subtotal is presented. This ASU also limits capitalization of net periodic benefit cost to the service cost component. The amendments in this update are effective for us beginning January 1, 2018. Upon adoption, the ASU requires that changes to the income statement presentation of net periodic benefit cost be applied retrospectively, while changes to amounts capitalized must be applied prospectively. We are currently assessing the effect of this standard on our financial statements and disclosures and anticipate the service cost component will be recognized in operations and maintenance expense, and the non-service cost component will be recognized in other income (expense), net. While the ASU limits capitalization of net periodic benefit cost to the service cost component, for rate making purposes, we do not expect there to be a change. As a result, we expect that the non-service cost component previously capitalized, will be reclassified to a regulatory asset. We do not anticipate any impact on net income from the adoption of this ASU. STATEMENT OF CASH FLOWS. On August 26, 2016, the FASB issued ASU 2016-15, "Classification of Certain Cash Receipts and Cash Payments." The ASU adds guidance pertaining to the classification of certain cash receipts and payments on the statement of cash flows. The purpose of the amendment is to clarify issues that have been creating diversity in practice, including the classification of proceeds from the settlement of insurance claims and proceeds from the settlement of corporate-owned life insurance policies. The amendments in this standard are effective for us beginning January 1, 2018. Early adoption is permitted in any interim or annual period. We are currently assessing the effect of this standard and do not expect this standard to materially affect our financial statements and disclosures. LEASES. On February 25, 2016, the FASB issued ASU 2016-02, "Leases," which revises the existing lease accounting guidance. Pursuant to the new standard, lessees will be required to recognize all leases, including operating leases that are greater than 12 months at lease commencement, on the balance sheet and record corresponding right-of-use assets and lease liabilities. Lessor accounting will remain substantially the same under the new standard. Quantitative and qualitative disclosures are also required for users of the financial statements to have a clear understanding of the nature of our leasing activities. The standard is effective for us beginning January 1, 2019, and early adoption is permitted. The new standard must be adopted using a modified retrospective transition and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. We are currently assessing the effect of this standard on our financial statements and disclosures. Refer to Note 14 of the 2016 Form 10-K for our current lease commitments. FINANCIAL INSTRUMENTS. On January 5, 2016, the FASB issued ASU 2016-01, "Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities." The ASU enhances the reporting model for financial instruments, which includes amendments to address aspects of recognition, measurement, presentation, and disclosure. The new standard is effective for us beginning January 1, 2018. Upon adoption, we will be required to make a cumulative-effect adjustment to the consolidated balance sheet in the first quarter of 2018. We do not expect this standard to have a material impact to our financial statements and disclosures. REVENUE RECOGNITION. On May 28, 2014, the FASB issued ASU 2014-09 "Revenue From Contracts with Customers." Subsequently, the FASB issued additional, clarifying amendments to address issues and questions regarding implementation of the new revenue recognition standard. The underlying principle of the guidance requires entities to recognize revenue depicting the transfer of goods or services to customers at amounts the entity is expected to be entitled to in exchange for those goods or services. The ASU also prescribes a five-step approach to revenue recognition: (1) identify the contract(s) with the customer; (2) identify the separate performance obligations in the contract(s); (3) determine the transaction price; (4) allocate the transaction price to separate performance obligations; and (5) recognize revenue when, or as, each performance obligation is satisfied. The guidance also requires additional disclosures, both qualitative and quantitative, regarding the nature, amount, timing and uncertainty of revenue and cash flows. The new requirements prescribe either a full retrospective or simplified transition adoption method. We are still evaluating the overall impacts of the standard and have not yet made a determination of adoption method. Some aspects we are focused on in our review include considering the impacts this new standard will have on alternative revenue streams and how collectability will be evaluated for certain customer classes. In August 2015, the FASB deferred the effective date by one year to January 1, 2018 for annual reporting periods beginning after December 15, 2017. We plan to adopt the new standard effective January 1, 2018. |
Earnings Per Share
Earnings Per Share | 3 Months Ended |
Mar. 31, 2017 | |
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | |
Earnings Per Share [Text Block] | 3. EARNINGS PER SHARE Basic earnings per share are computed using net income and the weighted average number of common shares outstanding for each period presented. Diluted earnings per share are computed in the same manner, except it uses the weighted average number of common shares outstanding plus the effects of the assumed exercise of stock options and the payment of estimated stock awards from other stock-based compensation plans that are outstanding at the end of each period presented. Antidilutive stock awards are excluded from the calculation of diluted earnings per common share. Diluted earnings per share are calculated as follows: Three Months Ended March 31, In thousands, except per share data 2017 2016 Net income $ 40,310 $ 36,641 Average common shares outstanding - basic 28,633 27,448 Additional shares for stock-based compensation plans (See Note 5) 90 112 Average common shares outstanding - diluted 28,723 27,560 Earnings per share of common stock - basic $ 1.41 $ 1.33 Earnings per share of common stock - diluted $ 1.40 $ 1.33 Additional information: Antidilutive shares 22 22 |
Segment Information
Segment Information | 3 Months Ended |
Mar. 31, 2017 | |
Segment Reporting [Abstract] | |
Segment Information [Text Block] | 4. SEGMENT INFORMATION We primarily operate in two reportable business segments: local gas distribution and gas storage. We also have other investments and business activities not specifically related to one of these two reporting segments, which are aggregated and reported as other. We refer to our local gas distribution business as the utility, and our gas storage segment and other as non-utility. Our utility segment also includes the utility portion of our Mist underground storage facility and our North Mist gas storage expansion in Oregon and NWN Gas Reserves, which is a wholly-owned subsidiary of Energy Corp. Our gas storage segment includes NWN Gas Storage, which is a wholly-owned subsidiary of NWN Energy, Gill Ranch, which is a wholly-owned subsidiary of NWN Gas Storage, the non-utility portion of Mist, and all third-party asset management services. Other includes NNG Financial and NWN Energy's equity investment in TWH, which is pursuing development of a cross-Cascades transmission pipeline project. See Note 4 in the 2016 Form 10-K for further discussion of our segments. Inter-segment transactions were insignificant for the periods presented. The following table presents summary financial information concerning the reportable segments: Three Months Ended March 31, In thousands Utility Gas Storage Other Total 2017 Operating revenues $ 292,726 $ 4,541 $ 56 $ 297,323 Depreciation and amortization 19,624 1,461 — 21,085 Income (loss) from operations 75,823 606 (201 ) 76,228 Net income (loss) 40,192 61 57 40,310 Capital expenditures 38,854 70 — 38,924 Total assets at March 31, 2017 2,799,638 254,260 16,758 3,070,656 2016 Operating revenues $ 250,104 $ 5,369 $ 56 $ 255,529 Depreciation and amortization 18,760 1,634 — 20,394 Income from operations 72,295 1,726 51 74,072 Net income 35,852 736 53 36,641 Capital expenditures 29,177 877 — 30,054 Total assets at March 31, 2016 2,726,696 260,535 14,802 3,002,033 Total assets at December 31, 2016 2,806,627 256,333 16,841 3,079,801 Utility Margin Utility margin is a financial measure consisting of utility operating revenues, which are reduced by revenue taxes, the associated cost of gas, and environmental recovery revenues. The cost of gas purchased for utility customers is generally a pass-through cost in the amount of revenues billed to regulated utility customers. Environmental recovery revenues represent collections received from customers through our environmental recovery mechanism in Oregon. These collections are offset by the amortization of environmental liabilities, which is presented as environmental remediation expense in our operating expenses. By subtracting cost of gas and environmental remediation expense from utility operating revenues, utility margin provides a key metric used by our chief operating decision maker in assessing the performance of the utility segment. The gas storage segment and other emphasize growth in operating revenues as opposed to margin because they do not incur a product cost (i.e. cost of gas sold) like the utility and, therefore, use operating revenues and net income to assess performance. The following table presents additional segment information concerning utility margin: Three Months Ended March 31, In thousands 2017 2016 Utility margin calculation: Utility operating revenues (1) $ 292,726 $ 250,104 Less: Utility cost of gas 143,611 108,411 Environmental remediation expense 6,954 5,029 Utility margin $ 142,161 $ 136,664 (1) Utility operating revenues include environmental recovery revenues, which are collections received from customers through our environmental recovery mechanism in Oregon, offset by environmental remediation expense. |
Stock-Based Compensation
Stock-Based Compensation | 3 Months Ended |
Mar. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock Based Compensation [Text Block] | 5. STOCK-BASED COMPENSATION Our stock-based compensation plans are designed to promote stock ownership in NW Natural by employees and officers. These compensation plans include a Long Term Incentive Plan (LTIP), an Employee Stock Purchase Plan (ESPP), and a Restated Stock Option Plan. For additional information on our stock-based compensation plans, see Note 6 in the 2016 Form 10-K and the updates provided below. Long Term Incentive Plan Performance Shares LTIP performance shares incorporate a combination of market, performance, and service-based factors. During the three months ended March 31, 2017 , 29,380 performance-based shares were granted under the LTIP based on target-level awards with a weighted-average grant date fair value of $ 57.05 per share. Award share payouts range from a threshold of 0% to a maximum of 200% based on achievement of EPS and Return on Invested Capital (ROIC) factors, which can be modified by a total shareholder return factor (TSR factor) relative to the performance of the Russell 2500 Utilities Index over the three -year performance period and a growth modifier based on a cumulative EBITDA measure. As of March 31, 2017 , there was $ 3.1 million of unrecognized compensation cost from LTIP grants, which is expected to be recognized through 2019 . Fair value for the shares granted during the three months ended March 31, 2017 , was estimated as of the date of grant using a Monte-Carlo option pricing model based on the following assumptions: Stock price on valuation date $ 59.90 Performance term (in years) 3.0 Quarterly dividends paid per share (1) $ 0.4700 Expected dividend yield 3.09 % Dividend discount factor 0.9156 (1) In addition to common stock shares, a participant also receives a dividend equivalent cash payment equal to the number of shares of common stock received on the award payout multiplied by the aggregate cash dividends paid per share during the performance period. Restricted Stock Units During the three months ended March 31, 2017 , 18,020 RSUs were granted under the LTIP with a weighted-average grant date fair value of $ 59.90 per share. Generally, the RSUs awarded are forfeitable and include a performance-based threshold as well as a vesting period of four years from the grant date. A RSU obligates us, upon vesting, to issue the RSU holder one share of common stock plus a cash payment equal to the total amount of dividends paid per share between the grant date and vesting date of that portion of the RSU. The fair value of a RSU is equal to the closing market price of our common stock on the grant date. As of March 31, 2017 , there was $ 3.1 million of unrecognized compensation cost from grants of RSUs, which is expected to be recognized over a period extending through 2022 . |
Debt
Debt | 3 Months Ended |
Mar. 31, 2017 | |
Debt Disclosure [Abstract] | |
Debt [Text Block] | 6. DEBT Short-Term Debt At March 31, 2017 , we had no outstanding short-term debt. Long-Term Debt At March 31, 2017 , we had long-term debt of $719.7 million , which included $7.0 million of unamortized debt issuance costs. Utility long-term debt consists of first mortgage bonds (FMBs) with maturity dates ranging from 2017 through 2046 , interest rates ranging from 1.545% to 9.05% , and a weighted-average coupon rate of 5.083% . Fair Value of Long-Term Debt Our outstanding debt does not trade in active markets. We estimate the fair value of our debt using utility companies with similar credit ratings, terms, and remaining maturities to our debt that actively trade in public markets. These valuations are based on Level 2 inputs as defined in the fair value hierarchy. See Note 2 in the 2016 Form 10-K for a description of the fair value hierarchy. The following table provides an estimate of the fair value of our long-term debt, including current maturities of long-term debt, using market prices in effect on the valuation date: March 31, December 31, In thousands 2017 2016 2016 Gross long-term debt $ 726,700 $ 601,700 $ 726,700 Unamortized debt issuance costs (6,990 ) (6,975 ) (7,377 ) Carrying amount $ 719,710 $ 594,725 $ 719,323 Estimated fair value (1) 785,980 686,159 793,339 (1) Estimated fair value does not include unamortized debt issuance costs. |
Pension and Other Postretiremen
Pension and Other Postretirement Benefits | 3 Months Ended |
Mar. 31, 2017 | |
Pension and Other Postretirement Benefit Expense [Abstract] | |
Pension and Other Postretirement Benefits [Text Block] | 7. PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS The following table provides the components of net periodic benefit cost for our pension and other postretirement benefit plans: Three Months Ended March 31, Pension Benefits Other Postretirement Benefits In thousands 2017 2016 2017 2016 Service cost $ 1,870 $ 1,944 $ 98 $ 121 Interest cost 4,472 4,574 274 300 Expected return on plan assets (5,113 ) (5,017 ) — — Amortization of prior service costs 32 58 (117 ) (117 ) Amortization of net actuarial loss 3,621 3,502 138 192 Net periodic benefit cost 4,882 5,061 393 496 Amount allocated to construction (1,521 ) (1,548 ) (132 ) (164 ) Amount deferred to regulatory balancing account (1) (1,527 ) (1,627 ) — — Net amount charged to expense $ 1,834 $ 1,886 $ 261 $ 332 (1) The deferral of defined benefit pension plan expenses above or below the amount set in rates was approved by the OPUC, with recovery of these deferred amounts through the implementation of a balancing account. The balancing account includes the expectation of higher net periodic benefit costs than costs recovered in rates in the near-term with lower net periodic benefit costs than costs recovered in rates expected in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the equity portion of the interest recognized when amounts are collected in rates. See Note 2 in the 2016 Form 10-K. The following table presents amounts recognized in accumulated other comprehensive loss (AOCL) and the changes in AOCL related to our non-qualified employee benefit plans: Three Months Ended March 31, In thousands 2017 2016 Beginning balance $ (6,951 ) $ (7,162 ) Amounts reclassified from AOCL: Amortization of actuarial losses 225 321 Total reclassifications before tax 225 321 Tax (benefit) expense (89 ) (127 ) Total reclassifications for the period 136 194 Ending balance $ (6,815 ) $ (6,968 ) Employer Contributions to Company-Sponsored Defined Benefit Pension Plans For the three months ended March 31, 2017 , we made cash contributions totaling $3.2 million to our qualified defined benefit pension plans. We expect further plan contributions of $16.2 million during the remainder of 2017 . Defined Contribution Plan The Retirement K Savings Plan is a qualified defined contribution plan under Internal Revenue Code Sections 401(a) and 401(k). Employer contributions totaled $1.6 million and $1.4 million for the three months ended March 31, 2017 and 2016 , respectively. See Note 8 in the 2016 Form 10-K for more information concerning these retirement and other postretirement benefit plans. |
Income Tax
Income Tax | 3 Months Ended |
Mar. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Tax [Text Block] | 8. INCOME TAX An estimate of annual income tax expense is made each interim period using estimates for annual pre-tax income, regulatory flow-through adjustments, tax credits, and other items. The estimated annual effective tax rate is applied to year-to-date, pre-tax income to determine income tax expense for the interim period consistent with the annual estimate. The effective income tax rate varied from the combined federal and state statutory tax rates due to the following: Three Months Ended March 31, Dollars in thousands 2017 2016 Income taxes at statutory rates (federal and state) $ 26,600 $ 24,608 Increase (decrease): Differences required to be flowed-through by regulatory commissions 1,518 1,518 Other, net (1,195 ) (740 ) Total provision for income taxes $ 26,923 $ 25,386 Effective tax rate 40.0 % 40.9 % The effective income tax rate for the three months ended March 31, 2017 , compared to the same period in 2016 , decreased primarily as a result of the equity portion of our allowance for funds used during construction (AFUDC) and increased stock-based compensation deductions in 2017. See Note 9 in the 2016 Form 10-K for more detail on income taxes and effective tax rates. The IRS Compliance Assurance Process (CAP) examination of the 2015 tax year was completed during the quarter. There were no material changes to the return as filed. The 2016 tax year is subject to examination under CAP and the 2017 tax year CAP application has been accepted by the IRS. |
Property, Plant and Equipment
Property, Plant and Equipment | 3 Months Ended |
Mar. 31, 2017 | |
Public Utilities, Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment [Text Block] | 9. PROPERTY, PLANT, AND EQUIPMENT The following table sets forth the major classifications of our property, plant, and equipment and accumulated depreciation: March 31, December 31, In thousands 2017 2016 2016 Utility plant in service $ 2,867,271 $ 2,760,188 $ 2,843,243 Utility construction work in progress 76,631 51,014 62,264 Less: Accumulated depreciation 914,179 878,364 903,096 Utility plant, net 2,029,723 1,932,838 2,002,411 Non-utility plant in service 299,324 296,826 299,378 Non-utility construction work in progress 3,951 7,826 3,931 Less: Accumulated depreciation 46,157 40,823 44,820 Non-utility plant, net 257,118 263,829 258,489 Total property, plant, and equipment $ 2,286,841 $ 2,196,667 $ 2,260,900 Capital expenditures in accrued liabilities $ 11,564 $ 8,424 $ 9,547 |
Gas Reserves
Gas Reserves | 3 Months Ended |
Mar. 31, 2017 | |
Gas Reserves [Abstract] | |
Gas Reserves [Text Block] | 10. GAS RESERVES We have invested $188 million through our gas reserves program in the Jonah Field located in Wyoming as of March 31, 2017 . Gas reserves are stated at cost, net of regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the consolidated balance sheets. Our investment in gas reserves provides long-term price protection for utility customers through the original agreement with Encana Oil & Gas (USA) Inc. under which we invested $178 million and the amended agreement with Jonah Energy LLC under which an additional $10 million was invested. The cost of gas, including a carrying cost for the rate base investment made under the original agreement, is included in our annual Oregon PGA filing, which allows us to recover these costs through customer rates. Our investment under the original agreement, less accumulated amortization and deferred taxes, earns a rate of return. The volumes produced from the wells under the amended agreement with Jonah are included in our Oregon PGA at a fixed rate of $0.4725 per therm, which approximates the 10-year hedge rate plus financing costs at the inception of the investment. The following table outlines our net gas reserves investment: March 31, December 31, In thousands 2017 2016 2016 Gas reserves, current $ 15,378 $ 16,420 $ 15,926 Gas reserves, non-current 172,158 171,121 171,610 Less: Accumulated amortization 75,528 59,976 71,426 Total gas reserves (1) 112,008 127,565 116,110 Less: Deferred taxes on gas reserves 32,179 28,547 28,119 Net investment in gas reserves $ 79,829 $ 99,018 $ 87,991 (1) Our net investment in additional wells included in total gas reserves was $ 6.5 million , $ 7.6 million and $ 6.7 million at March 31, 2017 and 2016 and December 31, 2016, respectively. Our investment is included in our consolidated balance sheets under gas reserves with our maximum loss exposure limited to our investment balance. |
Investments
Investments | 3 Months Ended |
Mar. 31, 2017 | |
Investments [Abstract] | |
Investments [Text Block] | 11. INVESTMENTS Investments in Gas Pipeline Trail West Pipeline, LLC (TWP), a wholly-owned subsidiary of TWH, is pursuing the development of a new gas transmission pipeline that would provide an interconnection with our utility distribution system. NWN Energy, a wholly-owned subsidiary of NW Natural, owns 50% of TWH, and 50% is owned by TransCanada American Investments Ltd., an indirect wholly-owned subsidiary of TransCanada Corporation. Variable Interest Entity (VIE) Analysis TWH is a VIE, with our investment in TWP reported under equity method accounting. We have determined we are not the primary beneficiary of TWH’s activities as we only have a 50% share of the entity and there are no stipulations that allow us a disproportionate influence over it. Our investments in TWH and TWP are included in other investments on our balance sheet. If we do not develop this investment, then our maximum loss exposure related to TWH is limited to our equity investment balance, less our share of any cash or other assets available to us as a 50% owner. Our investment balance in TWH was $13.4 million at March 31, 2017 and 2016 and December 31, 2016 . See Note 12 in the 2016 Form 10-K. Other Investments Other investments include financial investments in life insurance policies, which are accounted for at cash surrender value, net of policy loans. See Note 12 in the 2016 Form 10-K. |
Derivative Instruments
Derivative Instruments | 3 Months Ended |
Mar. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments [Text Block] | 12. DERIVATIVE INSTRUMENTS We enter into financial derivative contracts to hedge a portion of our utility’s natural gas sales requirements. These contracts include swaps, options and combinations of option contracts. We primarily use these derivative financial instruments to manage commodity price variability. A small portion of our derivative hedging strategy involves foreign currency exchange contracts. We enter into these financial derivatives, up to prescribed limits, primarily to hedge price variability related to our physical gas supply contracts as well as to hedge spot purchases of natural gas. The foreign currency forward contracts are used to hedge the fluctuation in foreign currency exchange rates for pipeline demand charges paid in Canadian dollars. In the normal course of business, we also enter into indexed-price physical forward natural gas commodity purchase contracts and options to meet the requirements of utility customers. These contracts qualify for regulatory deferral accounting treatment. We also enter into exchange contracts related to the third-party asset management of our gas portfolio, some of which are derivatives that do not qualify for hedge accounting or regulatory deferral, but are subject to our regulatory sharing agreement. These derivatives are recognized in operating revenues in our gas storage segment, net of amounts shared with utility customers. Notional Amounts The following table presents the absolute notional amounts related to open positions on our derivative instruments: March 31, December 31, In thousands 2017 2016 2016 Natural gas (in therms): Financial 382,850 317,100 477,430 Physical 368,700 169,978 535,450 Foreign exchange $ 6,629 $ 6,852 $ 7,497 Purchased Gas Adjustment (PGA) Derivatives entered into by the utility for the procurement or hedging of natural gas for future gas years generally receive regulatory deferral accounting treatment. In general, our commodity hedging for the current gas year is completed prior to the start of the gas year, and hedge prices are reflected in our weighted-average cost of gas in the PGA filing. Hedge contracts entered into after the start of the PGA period are subject to our PGA incentive sharing mechanism in Oregon. As of November 1, 2016 and 2015, we reached our target hedge percentage of approximately 75% for the 2016-17 and 2015-16 gas years. Hedge contracts entered into prior to our PGA filing, in September 2016, were included in the PGA for the 2016-17 gas year. Hedge contracts entered into after our PGA filing, and related to subsequent gas years, may be included in future PGA filings and qualify for regulatory deferral. Unrealized and Realized Gain/Loss The following table reflects the income statement presentation for the unrealized gains and losses from our derivative instruments: Three Months Ended March 31, 2017 2016 In thousands Natural gas commodity Foreign exchange Natural gas commodity Foreign exchange Benefit (expense) to cost of gas $ (13,094 ) $ 26 $ (7,215 ) $ 404 Operating loss (1,226 ) — — — Amounts deferred to regulatory accounts on balance sheet 13,893 (26 ) 7,215 (404 ) Total loss in pre-tax earnings $ (427 ) $ — $ — $ — UNREALIZED GAIN/LOSS. Outstanding derivative instruments related to regulated utility operations are deferred in accordance with regulatory accounting standards. The cost of foreign currency forward and natural gas derivative contracts are recognized immediately in the cost of gas; however, costs above or below the amount embedded in the current year PGA are subject to a regulatory deferral tariff and therefore, are recorded as a regulatory asset or liability. REALIZED GAIN/LOSS. We realized net losses of $0.3 million and $15.5 million for the three months ended March 31, 2017 and 2016 , respectively, from the settlement of natural gas financial derivative contracts. Realized gains and losses are recorded in cost of gas, deferred through our regulatory accounts, and amortized through customer rates in the following year. Credit Risk Management of Financial Derivatives Instruments No collateral was posted with or by our counterparties as of March 31, 2017 or 2016 . We attempt to minimize the potential exposure to collateral calls by counterparties to manage our liquidity risk. Counterparties generally allow a certain credit limit threshold before requiring us to post collateral against loss positions. Given our counterparty credit limits and portfolio diversification, we were not subject to collateral calls in 2017 or 2016 . Our collateral call exposure is set forth under credit support agreements, which generally contain credit limits. We could also be subject to collateral call exposure where we have agreed to provide adequate assurance, which is not specific as to the amount of credit limit allowed, but could potentially require additional collateral in the event of a material adverse change. Based upon current commodity financial swap and option contracts outstanding, which reflect unrealized losses of $1.4 million at March 31, 2017 , we have estimated the level of collateral demands, with and without potential adequate assurance calls, using current gas prices and various credit downgrade rating scenarios for NW Natural as follows: Credit Rating Downgrade Scenarios In thousands (Current Ratings) A+/A3 BBB+/Baa1 BBB/Baa2 BBB-/Baa3 Speculative With Adequate Assurance Calls $ — $ — $ — $ (1,065 ) $ (522 ) Without Adequate Assurance Calls — — — (1,065 ) (160 ) Our financial derivative instruments are subject to master netting arrangements; however, they are presented on a gross basis in our consolidated balance sheets. The Company and its counterparties have the ability to set-off their obligations to each other under specified circumstances. Such circumstances may include a defaulting party, a credit change due to a merger affecting either party, or any other termination event. If netted by counterparty, our derivative position would result in an asset of $1.7 million and a liability of $2.9 million as of March 31, 2017 . As of March 31, 2016 , our derivative position would have resulted in an asset of $ 1.8 million and a liability of $ 17.9 million . As of December 31, 2016 , our derivative position would have resulted in an asset of $ 18.8 million and a liability of $ 0.7 million . We are exposed to derivative credit and liquidity risk primarily through securing fixed price natural gas commodity swaps to hedge the risk of price increases for our natural gas purchases made on behalf of customers. See Note 13 in our 2016 Form 10-K for additional information. Fair Value In accordance with fair value accounting, we include non-performance risk in calculating fair value adjustments. This includes a credit risk adjustment based on the credit spreads of our counterparties when we are in an unrealized gain position, or on our own credit spread when we are in an unrealized loss position. The inputs in our valuation models include natural gas futures, volatility, credit default swap spreads and interest rates. Additionally, our assessment of non-performance risk is generally derived from the credit default swap market and from bond market credit spreads. The impact of the credit risk adjustments for all outstanding derivatives was immaterial to the fair value calculation at March 31, 2017 . As of March 31, 2017 and 2016 , and December 31, 2016 , the net fair value was a liability of $ 1.2 million , a liability of $ 16.1 million , and an asset $ 18.1 million , respectively, using significant other observable, or level 2, inputs. No level 3 inputs were used in our derivative valuations, and there were no transfers between level 1 or level 2 during the three months ended March 31, 2017 and 2016 . See Note 2 in the 2016 Form 10-K. |
Environmental Matters
Environmental Matters | 3 Months Ended |
Mar. 31, 2017 | |
Environmental Remediation Obligations [Abstract] | |
Environmental Matters [Text Block] | 13. ENVIRONMENTAL MATTERS We own, or previously owned, properties that may require environmental remediation or action. We estimate the range of loss for environmental liabilities based on current remediation technology, enacted laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties (PRPs). When amounts are prudently expended related to site remediation, of those sites described herein, we have a recovery mechanism in place to collect 96.68% of remediation costs from Oregon customers, and we are allowed to defer environmental remediation costs allocated to customers in Washington annually until they are reviewed for prudence at a subsequent proceeding. Our sites are subject to the remediation process prescribed by the Environmental Protection Agency (EPA) and the Oregon Department of Environmental Quality (ODEQ). The process begins with a remedial investigation (RI) to determine the nature and extent of contamination and then a risk assessment (RA) to establish whether the contamination at the site poses unacceptable risks to humans and the environment. Next, a feasibility study (FS) or an engineering evaluation/cost analysis (EE/CA) evaluates various remedial alternatives. It is at this point in the process when we are able to estimate a range of remediation costs and record a reasonable potential remediation liability, or make an adjustment to our existing liability. From this study, the regulatory agency selects a remedy and issues a Record of Decision (ROD). After a ROD is issued, we would seek to negotiate a consent decree or consent judgment for designing and implementing the remedy. We would have the ability to further refine estimates of remediation liabilities at that time. Remediation may include treatment of contaminated media such as sediment, soil and groundwater, removal and disposal of media, institutional controls such as legal restrictions on future property use, or natural recovery. Following construction of the remedy, the EPA and ODEQ also have requirements for ongoing maintenance, monitoring and other post-remediation care that may continue for many years. Where appropriate and reasonably known, we will provide for these costs in our remediation liabilities described below. Due to the numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several site investigations, in some cases, we may not be able to reasonably estimate the high end of the range of possible loss. In those cases, we have disclosed the nature of the possible loss and the fact that the high end of the range cannot be reasonably estimated where a range of potential loss is available. Unless there is an estimate within the range of possible losses that is more likely than other cost estimates within that range, we record the liability at the low end of this range. It is likely changes in these estimates and ranges will occur throughout the remediation process for each of these sites due to our continued evaluation and clarification concerning our responsibility, the complexity of environmental laws and regulations and the determination by regulators of remediation alternatives. In addition to remediation costs, we could also be subject to Natural Resource Damages (NRD) claims. We will assess the likelihood and probability of each claim and recognize a liability if deemed appropriate. We received a claim made by the Yakama Nation on January 31, 2017 for costs related to the selection of remedial action and certain declaratory relief regarding NRD. We are currently in the process of assessing the nature of, and our potential liability related to, the claim. Environmental Sites The following table summarizes information regarding liabilities related to environmental sites, which are recorded in other current liabilities and other noncurrent liabilities on the balance sheet: Current Liabilities Non-Current Liabilities March 31, December 31, March 31, December 31, In thousands 2017 2016 2016 2017 2016 2016 Portland Harbor site: Gasco/Siltronic Sediments $ 1,573 $ 2,747 $ 869 $ 43,200 $ 42,079 $ 43,972 Other Portland Harbor 1,804 1,655 1,970 3,940 4,775 4,148 Gasco/Siltronic Upland site 10,335 10,626 10,657 50,189 51,403 49,183 Central Service Center site 68 25 73 — — — Front Street site 858 1,071 906 7,777 7,746 7,786 Oregon Steel Mills — — — 179 179 179 Total $ 14,638 $ 16,124 $ 14,475 $ 105,285 $ 106,182 $ 105,268 PORTLAND HARBOR SITE. The Portland Harbor is an EPA listed Superfund site that is approximately 10 miles long on the Willamette River and is adjacent to NW Natural's Gasco uplands sites. We are one of over one hundred PRPs to the Superfund site. In January 2017, the EPA issued its Record of Decision, which outlines its determination of a cleanup approach for the Portland Harbor site (Portland Harbor ROD). The Portland Harbor ROD presents the EPA's decision on remedial alternatives and outlines the clean-up plan for the entire Portland Harbor. The Portland Harbor ROD estimates the present value total cost at approximately $1.05 billion with an accuracy between -30% and +50% of actual costs. Our potential liability is a portion of the costs of the remedy for the entire Portland Harbor Superfund site. The cost of that remedy is expected to be allocated among more than 100 PRPs. In addition, we are actively pursuing clarification and flexibility under the ROD in order to better understand our obligation under the clean-up. We are also participating in a non-binding allocation process in an effort to resolve our potential liability. The Portland Harbor ROD does not provide any additional clarification around allocation of costs among PRPs and, as a result of issuance of the Portland Harbor ROD, we have not modified any of our recorded liabilities at this time. We manage our liability related to the Superfund site as two distinct remediation projects, the Gasco/Siltronic Sediments and Other Portland Harbor projects. Gasco/Siltronic Sediments. In 2009, NW Natural and Siltronic Corporation entered into a separate Administrative Order on Consent with the EPA to evaluate and design specific remedies for sediments adjacent to the Gasco uplands and Siltronic uplands sites. We submitted a draft EE/CA to the EPA in May 2012 to provide the estimated cost of potential remedial alternatives for this site. At this time, the estimated costs for the various sediment remedy alternatives in the draft EE/CA as well as costs for the additional studies and design work needed before the cleanup can occur, and for regulatory oversight throughout the clean-up range from $44.8 million to $350 million . We have recorded a liability of $ 44.8 million for the sediment clean-up, which reflects the low end of the range. At this time, we believe sediments at this site represent the largest portion of our liability related to the Portland Harbor site, discussed above. Other Portland Harbor. While we still believe liabilities associated with Gasco/Siltronic sediments site represent our largest exposure, we do have other potential exposures associated with the Portland Harbor ROD, including NRD costs and harbor wide clean-up costs (including downstream petroleum contamination), for which the allocations among the PRP's have not yet been determined. The Company and other parties have signed a cooperative agreement with the Portland Harbor Natural Resource Trustee council to participate in a phased NRD assessment to estimate liabilities to support an early restoration-based settlement of NRD claims. One member of this Trustee council, the Yakama Nation, withdrew from the council in June 2009, and in January 2017, filed suit against the Company and 31 other parties seeking remedial costs and NRD assessment costs associated with the Portland Harbor, set forth in the complaint. The complaint seeks recovery of alleged costs totaling $0.3 million in connection with the selection of a remedial action for the Portland Harbor as well as declaratory judgment for unspecified future remedial action costs and for costs to assess the injury, loss or destruction of natural resources resulting from the release of hazardous substances at and from the Portland Harbor site. We have recorded a liability for these claims which is at the low end of the range of the potential liability; the high end of the range cannot be reasonably estimated at this time. The NRD liability is not included in the range of costs provided in the Portland Harbor ROD. GASCO UPLANDS SITE. A predecessor of NW Natural, Portland Gas and Coke Company, owned a former gas manufacturing plant that was closed in 1958 (Gasco site) and is adjacent to the Portland Harbor site described above. The Gasco site has been under investigation by us for environmental contamination under the ODEQ Voluntary Clean-Up Program (VCP). It is not included in the range of remedial costs for the Portland Harbor site noted above. We manage the Gasco site in two parts, the uplands portion and the groundwater source control action. We submitted a revised Remedial Investigation Report for the uplands to ODEQ in May 2007. In March 2015, ODEQ approved the RA NW Natural submitted in 2010, enabling us to begin work on the FS in 2016. We have recognized a liability for the remediation of the uplands portion of the site which is at the low end of the range of potential liability; the high end of the range cannot be reasonably estimated at this time. In October 2016, ODEQ and NW Natural agreed to amend their VCP agreement to incorporate a portion of the Siltronic property adjacent to the Gasco site formerly owned by Portland Gas & Coke between 1939 and 1960 into the Gasco RA and FS. Previously we were conducting an investigation of manufactured gas plant constituents on the entire Siltronic uplands for ODEQ. Siltronic will be working with ODEQ directly on environmental impacts to the remainder of its property. In September 2013, we completed construction of a groundwater source control system, including a water treatment station, at the Gasco site. We have estimated the cost associated with the ongoing operation of the system and have recognized a liability which is at the low end of the range of potential cost. We cannot estimate the high end of the range at this time due to the uncertainty associated with the duration of running the water treatment station, which is highly dependent on the remedy determined for both the upland portion as well as the final remedy for our Gasco sediment exposure. OTHER SITES. In addition to those sites above, we have environmental exposures at three other sites: Central Service Center, Front Street and Oregon Steel Mills. We may have exposure at other sites that have not been identified at this time. Due to the uncertainty of the design of remediation, regulation, timing of the remediation and in the case of the Oregon Steel Mills site, pending litigation, liabilities for each of these sites have been recognized at their respective low end of the range of potential liability; the high end of the range could not be reasonably estimated at this time. Central Service Center site . We are currently performing an environmental investigation of the property under ODEQ's Independent Cleanup Pathway. This site is on ODEQ's list of sites with confirmed releases of hazardous substances, and cleanup is necessary. Front Street site. The Front Street site was the former location of a gas manufacturing plant we operated (the former Portland Gas Manufacturing site, or PGM). At ODEQ’s request, we conducted a sediment and source control investigation and provided findings to ODEQ. In December 2015, we completed a FS on the former Portland Gas Manufacturing site. The FS provided a range of $7.6 million to $12.9 million for remedial costs. We have recorded a liability at the low end of the range of possible loss as no alternative in the range is considered more likely than another. Further, we have recognized an additional liability of $1.0 million for additional studies and design costs as well as regulatory oversight throughout the clean-up that will be required to assist in ODEQ making a remedy selection and completing a design. Oregon Steel Mills site . Refer to the “Legal Proceedings,” below. Site Remediation and Recovery Mechanism (SRRM) We have a SRRM through which we track and have the ability to recover past deferred and future prudently incurred environmental remediation costs allocable to Oregon, subject to an earnings test, for those sites identified herein. In the February 2015 Order establishing the SRRM (2015 Order), the OPUC addressed outstanding issues related to the SRRM, which required us to forego the collection of $15 million out of approximately $95 million in total environmental remediation expenses and associated carrying costs. As a follow-up to the 2015 Order, the OPUC issued an additional Order in January 2016 (2016 Order) regarding the SRRM implementation which resulted in a $ 3.3 million non-cash charge primarily due to the disallowance of interest earned on the original allowance. COLLECTIONS FROM OREGON CUSTOMERS. Under the SRRM collection process there are three types of deferred environmental remediation expense: • Pre-review - This class of costs represents remediation spend that has not yet been deemed prudent by the OPUC. Carrying costs on these remediation expenses are recorded at our authorized cost of capital. The Company anticipates the prudence review for annual costs and approval of the earnings test prescribed by the OPUC to occur by the third quarter of the following year. • Post-review - This class of costs represents remediation spend that has been deemed prudent and allowed after applying the earnings test, but is not yet included in amortization. We earn a carrying cost on these amounts at a rate equal to the five-year treasury rate plus 100 basis points. • Amortization - This class of costs represents amounts included in current customer rates for collection and is generally calculated as one-fifth of the post-review deferred balance. We earn a carrying cost equal to the amortization rate determined annually by the OPUC, which approximates a short-term borrowing rate. In addition to the collection amount noted above, the Order also provides for the annual collection of $5 million from Oregon customers through a tariff rider. As we collect amounts from customers, we recognize these collections as revenue and separately amortize an equal and offsetting amount of our deferred regulatory asset balance through the environmental remediation operating expense line shown separately in the operating expense section of the income statement. We received total environmental insurance proceeds of approximately $150 million as a result of settlements from our litigation that was dismissed in July 2014. Under the 2015 OPUC Order, one-third of the Oregon allocated proceeds were applied to costs deferred through 2012 with the remaining two-thirds applied to costs at a rate of $5 million per year plus interest over the following 20 years. We accrue interest on the insurance proceeds in the customer’s favor at a rate equal to the five-year treasury rate plus 100 basis points. As of March 31, 2017 , we have applied $63.2 million of insurance proceeds to prudently incurred remediation costs. The following table presents information regarding the total regulatory asset deferred: March 31, December 31, In thousands 2017 2016 2016 Deferred costs and interest (1) $ 49,373 $ 57,359 $ 53,039 Accrued site liabilities (2) 119,623 122,306 119,443 Insurance proceeds and interest (99,195 ) (102,570 ) (98,523 ) Total regulatory asset deferral (1) $ 69,801 $ 77,095 $ 73,959 Current regulatory assets (3) 7,574 9,096 9,989 Long-term regulatory assets (3) 62,227 67,999 63,970 (1) Includes pre-review and post-review deferred costs, amounts currently in amortization, and interest, net of amounts collected from customers. (2) Excludes $0.3 million, or 3.32% of the Front Street site liability as the OPUC allows recovery of 96.68% of costs for those sites allocable to Oregon, including those that historically served only Oregon customers. (3) Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and WUTC. In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, a carrying charge related to deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million tariff rider. The amounts allocable to Oregon are recoverable through utility rates, subject to an earnings test. ENVIRONMENTAL EARNINGS TEST. To the extent the utility earns at or below its authorized Return on Equity (ROE), remediation expenses and interest in excess of the $5 million tariff rider and $5 million insurance proceeds are recoverable through the SRRM. To the extent the utility earns more than its authorized ROE in a year, the utility is required to cover environmental expenses and interest on expenses greater than the $10 million with those earnings that exceed its authorized ROE. Under the 2015 Order, the OPUC will revisit the deferral and amortization of future remediation expenses, as well as the treatment of remaining insurance proceeds three years from the original Order, or earlier if the Company gains greater certainty about its future remediation costs, to consider whether adjustments to the mechanism may be appropriate. WASHINGTON DEFERRAL. In Washington, cost recovery and carrying charges on amounts deferred for costs associated with services provided to Washington customers will be determined in a future proceeding. Annually, we review all regulatory assets for recoverability or more often if circumstances warrant. If we should determine all or a portion of these regulatory assets no longer meet the criteria for continued application of regulatory accounting, then we would be required to write off the net unrecoverable balances against earnings in the period such a determination is made. Legal Proceedings NW Natural is subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings cannot be predicted with certainty, including the matter described below, we do not expect that the ultimate disposition of any of these matters will have a material effect on our financial condition, results of operations or cash flows. See also Part II, Item 1, “ Legal Proceedings .” OREGON STEEL MILLS SITE. In 2004, NW Natural was served with a third-party complaint by the Port of Portland (the Port) in a Multnomah County Circuit Court case, Oregon Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the 1940s and 1950s petroleum wastes generated by our predecessor, Portland Gas & Coke Company, and 10 other third-party defendants, were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Evraz Oregon Steel Mills. The complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. No date has been set for trial. Although the final outcome of this proceeding cannot be predicted with certainty, we do not expect the ultimate disposition of this matter will have a material effect on our financial condition, results of operations or cash flows. For additional information regarding other commitments and contingencies, see Note 14 in the 2016 Form 10-K. |
Summary of Significant Accoun20
Summary of Significant Accounting Policies (Policies) | 3 Months Ended |
Mar. 31, 2017 | |
Accounting Policies [Abstract] | |
Consolidation, Policy [Policy Text Block] | Our core utility business assets and operating activities are largely included in the parent company, NW Natural. Our direct and indirect wholly-owned subsidiaries include NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), Gill Ranch Storage, LLC (Gill Ranch), NNG Financial Corporation (NNG Financial), Northwest Energy Corporation (Energy Corp), and NWN Gas Reserves LLC (NWN Gas Reserves). Investments in corporate joint ventures and partnerships we do not directly or indirectly control, and for which we are not the primary beneficiary, are accounted for under the equity method, which includes NWN Energy’s investment in Trail West Holdings, LLC (TWH) and NNG Financial's investment in Kelso-Beaver (KB) Pipeline. NW Natural and its affiliated companies are collectively referred to herein as NW Natural. The consolidated financial statements are presented after elimination of all intercompany balances and transactions. In this report, the term “utility” is used to describe our regulated gas distribution business, and the term “non-utility” is used to describe our gas storage businesses and other non-utility investments and business activities. Information presented in these interim consolidated financial statements is unaudited, but includes all material adjustments management considers necessary for fair statement of the results for each period reported including normal recurring accruals. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in our 2016 Annual Report on Form 10-K (2016 Form 10-K). A significant part of our business is of a seasonal nature; therefore, results of operations for interim periods are not necessarily indicative of full year results. |
Use of Estimates, Policy [Policy Text Block] | |
Public Utilities, Policy [Policy Text Block] | Industry Regulation In applying regulatory accounting principles, we capitalize or defer certain costs and revenues as regulatory assets and liabilities pursuant to orders of the Public Utility Commission of Oregon (OPUC) or Washington Utilities and Transportation Commission (WUTC), which provide for the recovery of revenues or expenses from, or refunds to, utility customers in future periods, including a return or a carrying charge in certain cases. |
New Accounting Pronouncements, Policy [Policy Text Block] | Recently Adopted Accounting Pronouncements There were no material changes to the recently adopted accounting policies described in Note 2 of the 2016 Form 10-K during the three months ended March 31, 2017 . Recently Issued Accounting Pronouncements RETIREMENT BENEFITS. On March 10, 2017, the FASB issued ASU 2017-07, "Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Benefit Cost." The ASU requires entities to disaggregate current service cost from the other components of net periodic benefit cost and present it with other current compensation costs for related employees in the income statement and to present the other components elsewhere in the income statement and outside of income from operations if that subtotal is presented. This ASU also limits capitalization of net periodic benefit cost to the service cost component. The amendments in this update are effective for us beginning January 1, 2018. Upon adoption, the ASU requires that changes to the income statement presentation of net periodic benefit cost be applied retrospectively, while changes to amounts capitalized must be applied prospectively. We are currently assessing the effect of this standard on our financial statements and disclosures and anticipate the service cost component will be recognized in operations and maintenance expense, and the non-service cost component will be recognized in other income (expense), net. While the ASU limits capitalization of net periodic benefit cost to the service cost component, for rate making purposes, we do not expect there to be a change. As a result, we expect that the non-service cost component previously capitalized, will be reclassified to a regulatory asset. We do not anticipate any impact on net income from the adoption of this ASU. STATEMENT OF CASH FLOWS. On August 26, 2016, the FASB issued ASU 2016-15, "Classification of Certain Cash Receipts and Cash Payments." The ASU adds guidance pertaining to the classification of certain cash receipts and payments on the statement of cash flows. The purpose of the amendment is to clarify issues that have been creating diversity in practice, including the classification of proceeds from the settlement of insurance claims and proceeds from the settlement of corporate-owned life insurance policies. The amendments in this standard are effective for us beginning January 1, 2018. Early adoption is permitted in any interim or annual period. We are currently assessing the effect of this standard and do not expect this standard to materially affect our financial statements and disclosures. LEASES. On February 25, 2016, the FASB issued ASU 2016-02, "Leases," which revises the existing lease accounting guidance. Pursuant to the new standard, lessees will be required to recognize all leases, including operating leases that are greater than 12 months at lease commencement, on the balance sheet and record corresponding right-of-use assets and lease liabilities. Lessor accounting will remain substantially the same under the new standard. Quantitative and qualitative disclosures are also required for users of the financial statements to have a clear understanding of the nature of our leasing activities. The standard is effective for us beginning January 1, 2019, and early adoption is permitted. The new standard must be adopted using a modified retrospective transition and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. We are currently assessing the effect of this standard on our financial statements and disclosures. Refer to Note 14 of the 2016 Form 10-K for our current lease commitments. FINANCIAL INSTRUMENTS. On January 5, 2016, the FASB issued ASU 2016-01, "Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities." The ASU enhances the reporting model for financial instruments, which includes amendments to address aspects of recognition, measurement, presentation, and disclosure. The new standard is effective for us beginning January 1, 2018. Upon adoption, we will be required to make a cumulative-effect adjustment to the consolidated balance sheet in the first quarter of 2018. We do not expect this standard to have a material impact to our financial statements and disclosures. REVENUE RECOGNITION. On May 28, 2014, the FASB issued ASU 2014-09 "Revenue From Contracts with Customers." Subsequently, the FASB issued additional, clarifying amendments to address issues and questions regarding implementation of the new revenue recognition standard. The underlying principle of the guidance requires entities to recognize revenue depicting the transfer of goods or services to customers at amounts the entity is expected to be entitled to in exchange for those goods or services. The ASU also prescribes a five-step approach to revenue recognition: (1) identify the contract(s) with the customer; (2) identify the separate performance obligations in the contract(s); (3) determine the transaction price; (4) allocate the transaction price to separate performance obligations; and (5) recognize revenue when, or as, each performance obligation is satisfied. The guidance also requires additional disclosures, both qualitative and quantitative, regarding the nature, amount, timing and uncertainty of revenue and cash flows. The new requirements prescribe either a full retrospective or simplified transition adoption method. We are still evaluating the overall impacts of the standard and have not yet made a determination of adoption method. Some aspects we are focused on in our review include considering the impacts this new standard will have on alternative revenue streams and how collectability will be evaluated for certain customer classes. In August 2015, the FASB deferred the effective date by one year to January 1, 2018 for annual reporting periods beginning after December 15, 2017. We plan to adopt the new standard effective January 1, 2018. |
Summary of Significant Accoun21
Summary of Significant Accounting Policies (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Accounting Policies [Abstract] | |
Schedule of Regulatory Assets [Table Text Block] | Regulatory Assets March 31, December 31, In thousands 2017 2016 2016 Current: Unrealized loss on derivatives (1) $ 1,580 $ 17,313 $ 1,315 Gas costs 2,757 7,978 6,830 Environmental costs (2) 7,574 9,096 9,989 Decoupling (3) 10,087 13,235 13,067 Other (4) 12,876 13,902 11,161 Total current $ 34,874 $ 61,524 $ 42,362 Non-current: Unrealized loss on derivatives (1) $ 2,546 $ 1,237 $ 913 Pension balancing (5) 53,105 46,247 50,863 Income taxes 36,591 40,106 38,670 Pension and other postretirement benefit liabilities 179,586 180,909 183,035 Environmental costs (2) 62,227 67,999 63,970 Gas costs 114 2,462 89 Decoupling (3) 2,803 2,641 5,860 Other (4) 12,085 9,789 14,130 Total non-current $ 349,057 $ 351,390 $ 357,530 |
Schedule of Regulatory Liabilities [Table Text Block] | Regulatory Liabilities March 31, December 31, In thousands 2017 2016 2016 Current: Gas costs $ 13,741 $ 22,098 $ 8,054 Unrealized gain on derivatives (1) 2,870 1,960 16,624 Other (4) 16,600 11,538 15,612 Total current $ 33,211 $ 35,596 $ 40,290 Non-current: Gas costs $ 4,740 $ 9,221 $ 1,021 Unrealized gain on derivatives (1) 46 452 3,265 Accrued asset removal costs (6) 345,614 331,000 341,107 Other (4) 7,187 6,088 3,926 Total non-current $ 357,587 $ 346,761 $ 349,319 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Earnings Per Share [Abstract] | |
EPS Calculation [Table Text Block] | Three Months Ended March 31, In thousands, except per share data 2017 2016 Net income $ 40,310 $ 36,641 Average common shares outstanding - basic 28,633 27,448 Additional shares for stock-based compensation plans (See Note 5) 90 112 Average common shares outstanding - diluted 28,723 27,560 Earnings per share of common stock - basic $ 1.41 $ 1.33 Earnings per share of common stock - diluted $ 1.40 $ 1.33 Additional information: Antidilutive shares 22 22 |
Segment Reporting (Tables)
Segment Reporting (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Segment Reporting [Abstract] | |
Schedule of Segment Reporting Information, by Segment [Table Text Block] | Three Months Ended March 31, In thousands Utility Gas Storage Other Total 2017 Operating revenues $ 292,726 $ 4,541 $ 56 $ 297,323 Depreciation and amortization 19,624 1,461 — 21,085 Income (loss) from operations 75,823 606 (201 ) 76,228 Net income (loss) 40,192 61 57 40,310 Capital expenditures 38,854 70 — 38,924 Total assets at March 31, 2017 2,799,638 254,260 16,758 3,070,656 2016 Operating revenues $ 250,104 $ 5,369 $ 56 $ 255,529 Depreciation and amortization 18,760 1,634 — 20,394 Income from operations 72,295 1,726 51 74,072 Net income 35,852 736 53 36,641 Capital expenditures 29,177 877 — 30,054 Total assets at March 31, 2016 2,726,696 260,535 14,802 3,002,033 Total assets at December 31, 2016 2,806,627 256,333 16,841 3,079,801 |
Utility Margin [Table Text Block] | Three Months Ended March 31, In thousands 2017 2016 Utility margin calculation: Utility operating revenues (1) $ 292,726 $ 250,104 Less: Utility cost of gas 143,611 108,411 Environmental remediation expense 6,954 5,029 Utility margin $ 142,161 $ 136,664 |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block] | Stock price on valuation date $ 59.90 Performance term (in years) 3.0 Quarterly dividends paid per share (1) $ 0.4700 Expected dividend yield 3.09 % Dividend discount factor 0.9156 |
Debt (Tables)
Debt (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Debt Disclosure [Abstract] | |
Fair Value Of Long Term Debt Table [Text Block] | March 31, December 31, In thousands 2017 2016 2016 Gross long-term debt $ 726,700 $ 601,700 $ 726,700 Unamortized debt issuance costs (6,990 ) (6,975 ) (7,377 ) Carrying amount $ 719,710 $ 594,725 $ 719,323 Estimated fair value (1) 785,980 686,159 793,339 |
Pension and Other Postretirem26
Pension and Other Postretirement Benefits (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Pension and Other Postretirement Benefit Expense [Abstract] | |
Schedule of Net Benefit Costs [Table Text Block] | Three Months Ended March 31, Pension Benefits Other Postretirement Benefits In thousands 2017 2016 2017 2016 Service cost $ 1,870 $ 1,944 $ 98 $ 121 Interest cost 4,472 4,574 274 300 Expected return on plan assets (5,113 ) (5,017 ) — — Amortization of prior service costs 32 58 (117 ) (117 ) Amortization of net actuarial loss 3,621 3,502 138 192 Net periodic benefit cost 4,882 5,061 393 496 Amount allocated to construction (1,521 ) (1,548 ) (132 ) (164 ) Amount deferred to regulatory balancing account (1) (1,527 ) (1,627 ) — — Net amount charged to expense $ 1,834 $ 1,886 $ 261 $ 332 |
Schedule of Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block] | Three Months Ended March 31, In thousands 2017 2016 Beginning balance $ (6,951 ) $ (7,162 ) Amounts reclassified from AOCL: Amortization of actuarial losses 225 321 Total reclassifications before tax 225 321 Tax (benefit) expense (89 ) (127 ) Total reclassifications for the period 136 194 Ending balance $ (6,815 ) $ (6,968 ) |
Income Tax (Tables)
Income Tax (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | Three Months Ended March 31, Dollars in thousands 2017 2016 Income taxes at statutory rates (federal and state) $ 26,600 $ 24,608 Increase (decrease): Differences required to be flowed-through by regulatory commissions 1,518 1,518 Other, net (1,195 ) (740 ) Total provision for income taxes $ 26,923 $ 25,386 Effective tax rate 40.0 % 40.9 % |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Public Utilities, Property, Plant and Equipment [Abstract] | |
Major Classifications Of Property, Plant And Equipment And Accumulated Depreciation [Text Block] | March 31, December 31, In thousands 2017 2016 2016 Utility plant in service $ 2,867,271 $ 2,760,188 $ 2,843,243 Utility construction work in progress 76,631 51,014 62,264 Less: Accumulated depreciation 914,179 878,364 903,096 Utility plant, net 2,029,723 1,932,838 2,002,411 Non-utility plant in service 299,324 296,826 299,378 Non-utility construction work in progress 3,951 7,826 3,931 Less: Accumulated depreciation 46,157 40,823 44,820 Non-utility plant, net 257,118 263,829 258,489 Total property, plant, and equipment $ 2,286,841 $ 2,196,667 $ 2,260,900 Capital expenditures in accrued liabilities $ 11,564 $ 8,424 $ 9,547 |
Gas Reserves (Tables)
Gas Reserves (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Gas Reserves [Abstract] | |
Gas Reserves Table [Text Block] | March 31, December 31, In thousands 2017 2016 2016 Gas reserves, current $ 15,378 $ 16,420 $ 15,926 Gas reserves, non-current 172,158 171,121 171,610 Less: Accumulated amortization 75,528 59,976 71,426 Total gas reserves (1) 112,008 127,565 116,110 Less: Deferred taxes on gas reserves 32,179 28,547 28,119 Net investment in gas reserves $ 79,829 $ 99,018 $ 87,991 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block] | March 31, December 31, In thousands 2017 2016 2016 Natural gas (in therms): Financial 382,850 317,100 477,430 Physical 368,700 169,978 535,450 Foreign exchange $ 6,629 $ 6,852 $ 7,497 |
Income Statement Presentation of Derivative Instruments [Text Block] | Three Months Ended March 31, 2017 2016 In thousands Natural gas commodity Foreign exchange Natural gas commodity Foreign exchange Benefit (expense) to cost of gas $ (13,094 ) $ 26 $ (7,215 ) $ 404 Operating loss (1,226 ) — — — Amounts deferred to regulatory accounts on balance sheet 13,893 (26 ) 7,215 (404 ) Total loss in pre-tax earnings $ (427 ) $ — $ — $ — |
Table Of Estimated Collateral Calls Table [Text Block] | Credit Rating Downgrade Scenarios In thousands (Current Ratings) A+/A3 BBB+/Baa1 BBB/Baa2 BBB-/Baa3 Speculative With Adequate Assurance Calls $ — $ — $ — $ (1,065 ) $ (522 ) Without Adequate Assurance Calls — — — (1,065 ) (160 ) |
Environmental Matters (Tables)
Environmental Matters (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Environmental Remediation Obligations [Abstract] | |
Schedule of Environmental Loss Contingencies by Site [Table Text Block] | Current Liabilities Non-Current Liabilities March 31, December 31, March 31, December 31, In thousands 2017 2016 2016 2017 2016 2016 Portland Harbor site: Gasco/Siltronic Sediments $ 1,573 $ 2,747 $ 869 $ 43,200 $ 42,079 $ 43,972 Other Portland Harbor 1,804 1,655 1,970 3,940 4,775 4,148 Gasco/Siltronic Upland site 10,335 10,626 10,657 50,189 51,403 49,183 Central Service Center site 68 25 73 — — — Front Street site 858 1,071 906 7,777 7,746 7,786 Oregon Steel Mills — — — 179 179 179 Total $ 14,638 $ 16,124 $ 14,475 $ 105,285 $ 106,182 $ 105,268 |
Environmental Regulatory Table [Table Text Block] | March 31, December 31, In thousands 2017 2016 2016 Deferred costs and interest (1) $ 49,373 $ 57,359 $ 53,039 Accrued site liabilities (2) 119,623 122,306 119,443 Insurance proceeds and interest (99,195 ) (102,570 ) (98,523 ) Total regulatory asset deferral (1) $ 69,801 $ 77,095 $ 73,959 Current regulatory assets (3) 7,574 9,096 9,989 Long-term regulatory assets (3) 62,227 67,999 63,970 |
Organization and Principles o32
Organization and Principles of Consolidation Organization and Principles of Consolidation (Details) | 3 Months Ended |
Mar. 31, 2017segment | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of Operating Segments | 2 |
Summary of Significant Accoun33
Summary of Significant Accounting Policies Regulatory Asset Disclosure (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 | Mar. 31, 2016 | |
Regulatory Assets [Line Items] | ||||
Regulatory Liability, Current | $ 33,211 | $ 40,290 | $ 35,596 | |
Regulatory Assets, Current | 34,874 | 42,362 | 61,524 | |
Regulatory Assets, Noncurrent | 349,057 | 357,530 | 351,390 | |
Regulatory Liability, Noncurrent | 357,587 | 349,319 | 346,761 | |
Unrealized Loss On Derivatives [Member] | ||||
Regulatory Assets [Line Items] | ||||
Regulatory Assets, Current | [1] | 1,580 | 1,315 | 17,313 |
Regulatory Assets, Noncurrent | [1] | 2,546 | 913 | 1,237 |
Asset Recoverable Gas Costs [Member] | ||||
Regulatory Assets [Line Items] | ||||
Regulatory Assets, Current | 2,757 | 6,830 | 7,978 | |
Regulatory Assets, Noncurrent | 114 | 89 | 2,462 | |
Environmental Restoration Costs [Member] | ||||
Regulatory Assets [Line Items] | ||||
Regulatory Assets, Current | [2],[3] | 7,574 | 9,989 | 9,096 |
Regulatory Assets, Noncurrent | [2],[3] | 62,227 | 63,970 | 67,999 |
Decoupling [Domain] | ||||
Regulatory Assets [Line Items] | ||||
Regulatory Assets, Current | [4] | 10,087 | 13,067 | 13,235 |
Regulatory Assets, Noncurrent | [4] | 2,803 | 5,860 | 2,641 |
Other Regulatory [Member] | ||||
Regulatory Assets [Line Items] | ||||
Regulatory Assets, Current | [5] | 12,876 | 11,161 | 13,902 |
Regulatory Assets, Noncurrent | [5] | 12,085 | 14,130 | 9,789 |
Pension Balancing [Member] | ||||
Regulatory Assets [Line Items] | ||||
Regulatory Assets, Noncurrent | [6] | 53,105 | 50,863 | 46,247 |
Deferred Income Tax Charge [Member] | ||||
Regulatory Assets [Line Items] | ||||
Regulatory Assets, Noncurrent | 36,591 | 38,670 | 40,106 | |
Pension and Other Postretirement Plans Costs [Member] | ||||
Regulatory Assets [Line Items] | ||||
Regulatory Assets, Noncurrent | 179,586 | 183,035 | 180,909 | |
Asset Recoverable Gas Costs [Member] | ||||
Regulatory Assets [Line Items] | ||||
Regulatory Liability, Current | 13,741 | 8,054 | 22,098 | |
Regulatory Liability, Noncurrent | 4,740 | 1,021 | 9,221 | |
Unrealized Loss On Derivatives [Member] | ||||
Regulatory Assets [Line Items] | ||||
Regulatory Liability, Current | [1] | 2,870 | 16,624 | 1,960 |
Regulatory Liability, Noncurrent | [1] | 46 | 3,265 | 452 |
Other Regulatory [Member] | ||||
Regulatory Assets [Line Items] | ||||
Regulatory Liability, Current | [5] | 16,600 | 15,612 | 11,538 |
Regulatory Liability, Noncurrent | [5] | 7,187 | 3,926 | 6,088 |
Removal Costs [Member] | ||||
Regulatory Assets [Line Items] | ||||
Regulatory Liability, Noncurrent | [7] | $ 345,614 | $ 341,107 | $ 331,000 |
[1] | Unrealized gains or losses on derivatives are non-cash items and, therefore, do not earn a rate of return or a carrying charge. These amounts are recoverable through utility rates as part of the annual Purchased Gas Adjustment (PGA) mechanism when realized at settlement. | |||
[2] | Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and WUTC. In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, a carrying charge related to deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million tariff rider. The amounts allocable to Oregon are recoverable through utility rates, subject to an earnings test. | |||
[3] | Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and WUTC. In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, recovery of deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from Oregon customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million tariff rider. The amounts allocable to Oregon are recoverable through utility rates, subject to the aforementioned earnings test. See Note 13. | |||
[4] | This deferral represents the margin adjustment resulting from differences between actual and expected volumes. | |||
[5] | These balances primarily consist of deferrals and amortizations under approved regulatory mechanisms. The accounts being amortized typically earn a rate of return or carrying charge. | |||
[6] | The deferral of certain pension expenses above or below the amount set in rates was approved by the OPUC, with recovery of these deferred amounts through the implementation of a balancing account, which includes the expectation of lower net periodic benefit costs in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the equity portion of interest income recognized when amounts are collected in rates. | |||
[7] | Estimated costs of removal on certain regulated properties are collected through rates. |
Summary of Significant Accoun34
Summary of Significant Accounting Policies Regulatory Liability Disclosure (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 | Mar. 31, 2016 | |
Regulatory Liabilities [Line Items] | ||||
Current Regulatory Liabilities | $ 33,211 | $ 40,290 | $ 35,596 | |
Regulatory liabilities | 357,587 | 349,319 | 346,761 | |
Gas Costs Payable [Member] | ||||
Regulatory Liabilities [Line Items] | ||||
Current Regulatory Liabilities | 13,741 | 8,054 | 22,098 | |
Regulatory liabilities | 4,740 | 1,021 | 9,221 | |
Unrealized Gain On Derivatives [Member] | ||||
Regulatory Liabilities [Line Items] | ||||
Current Regulatory Liabilities | [1] | 2,870 | 16,624 | 1,960 |
Regulatory liabilities | [1] | 46 | 3,265 | 452 |
Other Regulatory [Member] | ||||
Regulatory Liabilities [Line Items] | ||||
Current Regulatory Liabilities | [2] | 16,600 | 15,612 | 11,538 |
Regulatory liabilities | [2] | 7,187 | 3,926 | 6,088 |
Asset Removal Costs [Member] | ||||
Regulatory Liabilities [Line Items] | ||||
Regulatory liabilities | [3] | $ 345,614 | $ 341,107 | $ 331,000 |
[1] | Unrealized gains or losses on derivatives are non-cash items and, therefore, do not earn a rate of return or a carrying charge. These amounts are recoverable through utility rates as part of the annual Purchased Gas Adjustment (PGA) mechanism when realized at settlement. | |||
[2] | These balances primarily consist of deferrals and amortizations under approved regulatory mechanisms. The accounts being amortized typically earn a rate of return or carrying charge. | |||
[3] | Estimated costs of removal on certain regulated properties are collected through rates. |
Earnings Per Share (Details)
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Earnings Per Share [Abstract] | ||
Net Income | $ 40,310 | $ 36,641 |
Average common shares outstanding - basic | 28,633 | 27,448 |
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements | 90 | 112 |
Average common shares outstanding - diluted | 28,723 | 27,560 |
Earnings per share of common stock - basic | $ 1.41 | $ 1.33 |
Earnings per share of common stock - diluted | $ 1.40 | $ 1.33 |
Antidilutive shares excluded from computation of earnings per share amount | 22 | 22 |
Segment Information (Details)
Segment Information (Details) $ in Thousands | 3 Months Ended | |||
Mar. 31, 2017USD ($)segment | Mar. 31, 2016USD ($) | Dec. 31, 2016USD ($) | ||
Segment Reporting Information [Line Items] | ||||
Operating revenues | $ 297,323 | $ 255,529 | ||
Cost of Gas | 143,611 | 108,411 | ||
Environmental Remediation Expense | 6,954 | 5,029 | ||
Depreciation and amortization | 21,085 | 20,394 | ||
Income from operations | 76,228 | 74,072 | ||
Net Income | 40,310 | 36,641 | ||
Capital expenditures | 38,924 | 30,054 | ||
Assets | $ 3,070,656 | 3,002,033 | $ 3,079,801 | |
Operating Segments [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Number of Reportable Segments | segment | 2 | |||
Operating Segments [Member] | Utility Segment [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | [1] | $ 292,726 | 250,104 | |
Cost of Gas | 143,611 | 108,411 | ||
Environmental Remediation Expense | 6,954 | 5,029 | ||
Gross Profit | 142,161 | 136,664 | ||
Depreciation and amortization | 19,624 | 18,760 | ||
Income from operations | 75,823 | 72,295 | ||
Net Income | 40,192 | 35,852 | ||
Capital expenditures | 38,854 | 29,177 | ||
Assets | 2,799,638 | 2,726,696 | 2,806,627 | |
Operating Segments [Member] | Gas Storage Segment [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 4,541 | 5,369 | ||
Depreciation and amortization | 1,461 | 1,634 | ||
Income from operations | 606 | 1,726 | ||
Net Income | 61 | 736 | ||
Capital expenditures | 70 | 877 | ||
Assets | 254,260 | 260,535 | 256,333 | |
Corporate, Non-Segment [Member] | Corporate and Other [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Operating revenues | 56 | 56 | ||
Depreciation and amortization | 0 | 0 | ||
Income from operations | (201) | 51 | ||
Net Income | 57 | 53 | ||
Capital expenditures | 0 | 0 | ||
Assets | $ 16,758 | $ 14,802 | $ 16,841 | |
[1] | Utility operating revenues include environmental recovery revenues, which are collections received from customers through our environmental recovery mechanism in Oregon, offset by environmental remediation expense. |
Stock-Based Compensation (Detai
Stock-Based Compensation (Details) | 3 Months Ended |
Mar. 31, 2017USD ($)$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Exercise Price | $ / shares | $ 59.90 |
Weighted Average Price Per LTIP | |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term | 3 years |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Payments | $ | $ 0.4700 |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate | 3.09% |
Share-based Compensation Arrangement by Share-based Payment Award, Discount from Market Price, Offering Date | 91.56% |
Long Term Incentive Plan [Member] | Performance Shares [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | shares | 29,380 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Intrinsic Value, Amount Per Share | $ / shares | $ 57.05 |
Weighted-Average Price Per Share | |
Unrecognized compensation expense | $ | $ 3,100,000 |
Unrecognized compensation cost, period for recognition | through 2,019 |
Long Term Incentive Plan [Member] | Performance Shares [Member] | Maximum [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Share-based Compensation Arrangements by Share-based Payment Award, Conversion Ratio, Percent of Target | 200.00% |
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | 3 years |
Long Term Incentive Plan [Member] | Performance Shares [Member] | Minimum [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Share-based Compensation Arrangements by Share-based Payment Award, Conversion Ratio, Percent of Target | 0.00% |
Long Term Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | 4 years |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Number of Common Shares to be Issued Per Award | shares | 1 |
Number of RSUs [Roll Forward] | |
Granted | shares | 18,020 |
Weighted-Average Price Per Share | |
Granted | $ / shares | $ 59.90 |
Unrecognized compensation expense | $ | $ 3,100,000 |
Unrecognized compensation cost, period for recognition | through 2,022 |
Debt (Details)
Debt (Details) - USD ($) | 3 Months Ended | ||
Mar. 31, 2017 | Dec. 31, 2016 | Mar. 31, 2016 | |
Debt Disclosure [Abstract] | |||
Short-term Debt | $ 0 | $ 53,300,000 | $ 164,900,000 |
Short-term Debt, Weighted Average Interest Rate | 5.083% | ||
Debt Outstanding | |||
Long-term Debt | 719,710,000 | 719,323,000 | $ 594,725,000 |
Unamortized Debt Issuance Expense | (6,990,000) | (7,377,000) | (6,975,000) |
Long-term Debt, Gross | $ 726,700,000 | 726,700,000 | 601,700,000 |
Debt Instrument, Maturity Date Range, Start | Aug. 1, 2017 | ||
Debt Instrument, Maturity Date Range, End | Dec. 5, 2046 | ||
Liabilities, Fair Value Disclosure [Abstract] | |||
Debt Instrument, Fair Value Disclosure | $ 785,980,000 | $ 793,339,000 | $ 686,159,000 |
Minimum [Member] | |||
Debt Outstanding | |||
Debt Instrument, Interest Rate, Stated Percentage | 1.545% | ||
Maximum [Member] | |||
Debt Outstanding | |||
Debt Instrument, Interest Rate, Stated Percentage | 9.05% |
Pension and Other Postretirem39
Pension and Other Postretirement Benefits (Details) - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2016 | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension and Other Postretirement Benefit Contributions | $ 3,200 | ||
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year | 16,200 | ||
Defined Contribution Plan, Cost Recognized | 1,600 | $ 1,400 | |
Defined Benefit Plan Amounts Recognized In Regulatory Amortization And Other Comprehensive Income Net Prior Service Cost Credit Before Tax [Abstract] | |||
Accumulated Other Comprehensive loss, beginning of period | (6,951) | (7,162) | |
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Benefit Cost, before Tax | 225 | 321 | |
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Tax | 225 | 321 | |
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Tax, Portion Attributable to Parent | (89) | (127) | |
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | 136 | 194 | |
Accumulated Other Comprehensive loss, end of period | (6,815) | (6,968) | |
Pension Plan [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract] | |||
Defined Benefit Plan, Service Cost | 1,870 | 1,944 | |
Defined Benefit Plan, Interest Cost | 4,472 | 4,574 | |
Defined Benefit Plan, Expected Return on Plan Assets | (5,113) | (5,017) | |
Defined Benefit Plan, Amortization of Transition Obligations (Assets) | 32 | 58 | |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | 3,621 | 3,502 | |
Defined Benefit Plan Net Periodic Benefit Cost | 4,882 | 5,061 | |
Defined Benefit Plan Amount Allocated To Construction | (1,521) | (1,548) | |
Defined Benefit Plan Net Amount Deferred To Regulatory Balancing Account | [1] | (1,527) | (1,627) |
Defined Benefit Plan Net Amount Charged To Expense | 1,834 | 1,886 | |
Other Postretirement Benefit Plan [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract] | |||
Defined Benefit Plan, Service Cost | 98 | 121 | |
Defined Benefit Plan, Interest Cost | 274 | 300 | |
Defined Benefit Plan, Expected Return on Plan Assets | 0 | 0 | |
Defined Benefit Plan, Amortization of Transition Obligations (Assets) | (117) | (117) | |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | 138 | 192 | |
Defined Benefit Plan Net Periodic Benefit Cost | 393 | 496 | |
Defined Benefit Plan Amount Allocated To Construction | (132) | (164) | |
Defined Benefit Plan Net Amount Deferred To Regulatory Balancing Account | [1] | 0 | 0 |
Defined Benefit Plan Net Amount Charged To Expense | $ 261 | $ 332 | |
[1] | The deferral of defined benefit pension plan expenses above or below the amount set in rates was approved by the OPUC, with recovery of these deferred amounts through the implementation of a balancing account. The balancing account includes the expectation of higher net periodic benefit costs than costs recovered in rates in the near-term with lower net periodic benefit costs than costs recovered in rates expected in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the equity portion of the interest recognized when amounts are collected in rates. See Note 2 in the 2016 Form 10-K. |
Income Tax (Details)
Income Tax (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Income Tax Disclosure [Abstract] | ||
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate | $ 26,600 | $ 24,608 |
Income Tax Reconciliation, Differences Regulatory Commission | 1,518 | 1,518 |
Income Tax Reconciliation, Other Adjustments | (1,195) | (740) |
Income Tax Expense (Benefit) | $ 26,923 | $ 25,386 |
Effective Income Tax Rate | 40.00% | 40.90% |
Property, Plant and Equipment41
Property, Plant and Equipment (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 | Mar. 31, 2016 |
Property, Plant and Equipment, Net, by Type [Abstract] | |||
Property, plant and equipment, gross | $ 3,247,177 | $ 3,208,816 | $ 3,115,854 |
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 960,336 | 947,916 | 919,187 |
Total property, plant, and equipment, net | 2,286,841 | 2,260,900 | 2,196,667 |
Property, Plant, Equipment non-cash | 11,564 | 9,547 | 8,424 |
Utility Plant [Member] | |||
Property, Plant and Equipment, Net, by Type [Abstract] | |||
Property, plant and equipment, gross | 2,867,271 | 2,843,243 | 2,760,188 |
Public Utilities, Property, Plant and Equipment, Construction Work in Progress | 76,631 | 62,264 | 51,014 |
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 914,179 | 903,096 | 878,364 |
Total property, plant, and equipment, net | 2,029,723 | 2,002,411 | 1,932,838 |
Non Utility Plant [Member] | |||
Property, Plant and Equipment, Net, by Type [Abstract] | |||
Property, plant and equipment, gross | 299,324 | 299,378 | 296,826 |
Public Utilities, Property, Plant and Equipment, Construction Work in Progress | 3,951 | 3,931 | 7,826 |
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 46,157 | 44,820 | 40,823 |
Total property, plant, and equipment, net | $ 257,118 | $ 258,489 | $ 263,829 |
Gas Reserves (Details)
Gas Reserves (Details) - USD ($) | 3 Months Ended | |||
Mar. 31, 2017 | Dec. 31, 2016 | Mar. 31, 2016 | ||
Gas Reserves [Abstract] | ||||
Total cumulative gas reserves investment | $ 188,000,000 | |||
Encana Gas reserves investment | 178,000,000 | |||
Cumulative gross investment Jonah Wells | 10,000,000 | |||
Additional Jonah Wells rate per therm | 0.4725 | |||
Gas Reserves, Current | 15,378,000 | $ 15,926,000 | $ 16,420,000 | |
Gas Reserves Noncurrent Gross | 172,158,000 | 171,610,000 | 171,121,000 | |
Gas Reserves Amortization | 75,528,000 | 71,426,000 | 59,976,000 | |
Total Gas Reserves | [1] | 112,008,000 | 116,110,000 | 127,565,000 |
Deferred Taxes Related To Gas Reserves | 32,179,000 | 28,119,000 | 28,547,000 | |
Net Gas Reserves Investment | 79,829,000 | 87,991,000 | 99,018,000 | |
Total gas reserves investment Jonah Wells | $ 6,500,000 | $ 6,700,000 | $ 7,600,000 | |
[1] | Our net investment in additional wells included in total gas reserves was $6.5 million, $7.6 million and $6.7 million at March 31, 2017 and 2016 and December 31, 2016, respectively. |
Investments (Details)
Investments (Details) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 | Mar. 31, 2016 |
Investments [Abstract] | |||
Ownership percentage of TWH | 50.00% | ||
Equity Method Investment, Underlying Equity in Net Assets | $ 13.4 | $ 13.4 | $ 13.4 |
Derivative Instruments Gain (Lo
Derivative Instruments Gain (Loss) by Hedging Relationship, by Income Statement Location, by Derivative Instrument Risk (Details) $ in Thousands | 3 Months Ended | ||||
Mar. 31, 2017USD ($)therm | Mar. 31, 2016USD ($)therm | Dec. 31, 2016USD ($)therm | Nov. 01, 2016 | Nov. 01, 2015 | |
Notional Disclosures [Abstract] | |||||
Financial Derivative, Nonmonetary Notional Amount | therm | 382,850,000 | 317,100,000 | 477,430,000 | ||
Derivative, Nonmonetary Notional Amount | therm | 368,700,000 | 169,978,000 | 535,450,000 | ||
Notional Amount of Foreign Currency Derivatives | $ 6,629 | $ 6,852 | $ 7,497 | ||
Derivative [Line Items] | |||||
Target Hedge 2015-2016 Gas Year | 75.00% | ||||
Target Hedge 2016-2017 Gas Year | 75.00% | ||||
General Discussion of Derivative Instruments and Hedging Activities [Abstract] | |||||
Derivative, Loss on Derivative | 300 | 15,500 | |||
Unrealized Gain (loss) On Derivatives | 1,400 | ||||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | 1,700 | 1,800 | 18,800 | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 2,900 | 17,900 | 700 | ||
Derivative Fair Value Of Derivative Net | (1,200) | (16,100) | $ 18,100 | ||
Natural gas commodity | |||||
Unrealized Gain/Loss [Abstract] | |||||
Amounts deferred to regulatory accounts on balance sheet | 13,893 | 7,215 | |||
Total loss in pre-tax earnings | (427) | 0 | |||
Foreign exchange | |||||
Unrealized Gain/Loss [Abstract] | |||||
Amounts deferred to regulatory accounts on balance sheet | (26) | (404) | |||
Total loss in pre-tax earnings | 0 | 0 | |||
Benefit (expense) to cost of gas | Natural gas commodity | |||||
Unrealized Gain/Loss [Abstract] | |||||
Amounts deferred and non-deferred | (13,094) | (7,215) | |||
Benefit (expense) to cost of gas | Foreign exchange | |||||
Unrealized Gain/Loss [Abstract] | |||||
Amounts deferred and non-deferred | 26 | 404 | |||
Operating loss | Natural gas commodity | |||||
Unrealized Gain/Loss [Abstract] | |||||
Amounts deferred and non-deferred | (1,226) | 0 | |||
Operating loss | Foreign exchange | |||||
Unrealized Gain/Loss [Abstract] | |||||
Amounts deferred and non-deferred | $ 0 | $ 0 |
Derivative Instruments Credit R
Derivative Instruments Credit Rating Downgrade Scenarios (Details) $ in Thousands | Mar. 31, 2017USD ($) |
Moody's, A3 Rating [Member] | |
Description Of Credit Risk Related Contingent Features [Line Items] | |
With Adequate Assurance Calls | $ 0 |
Without Adequate Assurance Calls | 0 |
Moody's, Baa1 Rating [Member] | |
Description Of Credit Risk Related Contingent Features [Line Items] | |
With Adequate Assurance Calls | 0 |
Without Adequate Assurance Calls | 0 |
Moody's, Baa2 Rating [Member] | |
Description Of Credit Risk Related Contingent Features [Line Items] | |
With Adequate Assurance Calls | 0 |
Without Adequate Assurance Calls | 0 |
Moody's, Baa3 Rating [Member] | |
Description Of Credit Risk Related Contingent Features [Line Items] | |
With Adequate Assurance Calls | (1,065) |
Without Adequate Assurance Calls | (1,065) |
Speculative [Member] | |
Description Of Credit Risk Related Contingent Features [Line Items] | |
With Adequate Assurance Calls | (522) |
Without Adequate Assurance Calls | $ (160) |
Environmental Matters (Details)
Environmental Matters (Details) | 3 Months Ended | |||
Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Mar. 31, 2016USD ($) | ||
Environmental Activity [Line Items] | ||||
Accrual for Environmental Loss Contingencies, Discount Rate | 1.00% | |||
Accrual for Environmental Loss Contingencies, Annual Amortization Rate | 0.20 | |||
Site Contingency, Recovery from Third Party of Environmental Cost, Interest Rate on Recognition | 1.00% | |||
Remediation recovery percentage in Oregon | 96.68% | |||
Portland Harbor EPA Clean-Up Present Value Cost | $ 1,050,000,000 | |||
Portland Harbor Number Of Potentially Responsible Parties | more than 100 | |||
Loss Contingency Range Of Possible Loss Gasco Siltronic | $44.8 million to $350 million | |||
Gasco Siltronic Sediments Project Liability | $ 44,800,000 | |||
NRD Liability Claim Yakama Nation | 300,000 | |||
Front Street liability for studies and design costs | 1,000,000 | |||
SRRM pre-tax regulatory disallowance | 15,000,000 | |||
Deferred environmental charges | 95,000,000 | |||
Total SRRM disallowance from February 2016 Order | 3,300,000 | |||
Annual tariff rider collection | 5,000,000 | |||
Environmental Settlement Insurance Proceeds Received To Date | 150,000,000 | |||
Annual insurance proceeds to apply against remediation costs | $ 5,000,000 | |||
Site Contingency, Recovery from Third Party of Environmental Cost, Recognition Term | 20 years | |||
Insurance proceeds applied to prudently incurred remediation costs | $ 63,200,000 | |||
Remediation non-recovery percentage for Oregon | 3.32% | |||
Annual Insurance Proceeds to Apply Against Remediation Costs | $ 5,000,000 | |||
Total Annual Remediation Expense and Interest | 10,000,000 | |||
Accrual for Environmental Loss Contingencies [Abstract] | ||||
Environmental Current Liabilities | 14,638,000 | $ 14,475,000 | $ 16,124,000 | |
Environmental Noncurrent Liabilities | 105,285,000 | 105,268,000 | 106,182,000 | |
Regulatory Assets, Current | 34,874,000 | 42,362,000 | 61,524,000 | |
Regulatory Assets, Noncurrent | 349,057,000 | 357,530,000 | 351,390,000 | |
Minimum [Member] | ||||
Environmental Activity [Line Items] | ||||
Portland Harbor EPA Clean-Up Present Value Cost | (0.30) | |||
Front Street Remedial Costs | 7,600,000 | |||
Maximum [Member] | ||||
Environmental Activity [Line Items] | ||||
Portland Harbor EPA Clean-Up Present Value Cost | 0.50 | |||
Front Street Remedial Costs | 12,900,000 | |||
Gasco Siltronic Sediments [Member] | ||||
Accrual for Environmental Loss Contingencies [Abstract] | ||||
Environmental Current Liabilities | 1,573,000 | 869,000 | 2,747,000 | |
Environmental Noncurrent Liabilities | 43,200,000 | 43,972,000 | 42,079,000 | |
Portland Harbor Other [Member] | ||||
Accrual for Environmental Loss Contingencies [Abstract] | ||||
Environmental Current Liabilities | 1,804,000 | 1,970,000 | 1,655,000 | |
Environmental Noncurrent Liabilities | 3,940,000 | 4,148,000 | 4,775,000 | |
Gasco Upland [Member] | ||||
Accrual for Environmental Loss Contingencies [Abstract] | ||||
Environmental Current Liabilities | 10,335,000 | 10,657,000 | 10,626,000 | |
Environmental Noncurrent Liabilities | 50,189,000 | 49,183,000 | 51,403,000 | |
Central Service Center [Member] | ||||
Accrual for Environmental Loss Contingencies [Abstract] | ||||
Environmental Current Liabilities | 68,000 | 73,000 | 25,000 | |
Environmental Noncurrent Liabilities | 0 | 0 | 0 | |
Front Street [Member] | ||||
Accrual for Environmental Loss Contingencies [Abstract] | ||||
Environmental Current Liabilities | 858,000 | 906,000 | 1,071,000 | |
Environmental Noncurrent Liabilities | 7,777,000 | 7,786,000 | 7,746,000 | |
Oregon Steel Mills [Member] | ||||
Accrual for Environmental Loss Contingencies [Abstract] | ||||
Environmental Current Liabilities | 0 | 0 | 0 | |
Environmental Noncurrent Liabilities | 179,000 | 179,000 | 179,000 | |
Environmental Restoration Costs [Member] | ||||
Environmental Activity [Line Items] | ||||
Environmental Regulatory Deferred Cost and Interest | [1] | 49,373,000 | 53,039,000 | 57,359,000 |
Environmental Regulatory Insurance Proceeds and Interest | (99,195,000) | (98,523,000) | (102,570,000) | |
Environmental Regulatory Accrued Site Liabilities | [2] | 119,623,000 | 119,443,000 | 122,306,000 |
Environmental Regulatory Table [Abstract] | ||||
Environmental Regulatory Assets Noncurrent | [1] | 69,801,000 | 73,959,000 | 77,095,000 |
Accrual for Environmental Loss Contingencies [Abstract] | ||||
Regulatory Assets, Current | [3],[4] | 7,574,000 | 9,989,000 | 9,096,000 |
Regulatory Assets, Noncurrent | [3],[4] | 62,227,000 | $ 63,970,000 | $ 67,999,000 |
Environmental Restoration Costs [Member] | Front Street [Member] | ||||
Environmental Activity [Line Items] | ||||
Environmental Regulatory Accrued Site Liabilities | $ 300,000 | |||
[1] | Includes pre-review and post-review deferred costs, amounts currently in amortization, and interest, net of amounts collected from customers. | |||
[2] | Excludes $0.3 million, or 3.32% of the Front Street site liability as the OPUC allows recovery of 96.68% of costs for those sites allocable to Oregon, including those that historically served only Oregon customers. | |||
[3] | Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and WUTC. In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, a carrying charge related to deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million tariff rider. The amounts allocable to Oregon are recoverable through utility rates, subject to an earnings test. | |||
[4] | Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and WUTC. In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, recovery of deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from Oregon customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million tariff rider. The amounts allocable to Oregon are recoverable through utility rates, subject to the aforementioned earnings test. See Note 13. |